One set of techniques to maximize hydrocarbon production is referred to as “stimulation.” Stimulation procedures are usually performed on production wells completed in oil and/or gas containing formations; however, injection wells used in secondary or tertiary recovery operations can also be fractured to facilitate the injection of the fluids.
One stimulation technique is hydraulic fracturing. Hydraulic fracturing involves injecting a fracturing fluid into the wellbore directed at the face of a hydrocarbon bearing geologic formation at pressures sufficient to initiate and extend a crack or cracks (fractures) in the formation. The continued pumping of the fracturing fluid extends the fractures. A proppant, such as sand or other particulate material, can be suspended in the fracturing fluid and introduced into the created fractures. The proppant material holds or “props” open the fracture and prevents the formed fractures from closing upon reduction of the hydraulic pressure. In this way, conductive channels remain through which produced fluids can readily flow to the wellbore upon completion of the fracturing treatment.
Thus, the purpose of the fracturing fluid generally is two-fold:
(1) to create a fracture(s) or extend an existing fracture(s) through high-pressure introduction of fluid into the geologic formation; and (2) to leave said crack(s) as conductive flow paths for the purpose of increasing hydrocarbon flow to the wellbore, or to improve the inductivity of some fluid into the reservoir rock. This is most typically accomplished by the transporting of some type of solid proppant into the fracture void space created by the fluid injection so that the proppant can prevent complete closure of the fracture(s) and create a porous channel through which fluid can more easily flow to (or from) the wellbore. For placing proppants into the fracture(s), the fracturing fluid of choice will often have a high viscosity to retain a proppant material in suspension (or semi-suspension) in order to help carry the proppant away from the wellbore into the created fracture(s). In some cases, a fracturing fluid may be at least partly composed of some type of chemical or additive that will dissolve a part of the formation rock along the wall of the fracture(s) to yield the benefit of creating an open flow path for production or injection of fluids (i.e., such as an acid dissolving a carbonate rock).
The basic component of the fracturing fluid is usually water, in which case it is an aqueous fracturing fluid, although other liquids and gases can also be included in the fluid. Water, as well as many of the other possible fracturing fluids, lacks adequate viscosity to suspend a proppant for very long, thereby depending mostly on fluid velocity as the dominant proppant transport mechanism. To increase the viscosity of the fluid, a viscosifying (thickening) agent is commonly used in a fracturing fluid. A fluid with a high-molecular weight system can form a viscous fluid or gel. Commonly used viscosifying agents include polymers, many of which are selected because they can be crosslinked to selectively form very high molecular weight systems. The most common viscosifying agent currently is guar, or some derivative of guar.
Once the proppant is transported into the fracture, it is then desirable to remove the viscosified fracturing fluid from the fracture. The process of removing the viscous fluid from the fracture after the suspended proppant in the viscous fluid has been transported into the fracture is sometimes referred to as “fracture clean-up.”
When a polymer or a crosslinked polymer is used as a viscosifying agent, a chemical additive, known in the art as a breaker, is normally also used, which is capable of at least partially destroying the crosslinking, partially degrading the polymer itself, or both. The purpose of the breaker is to lower the viscosity of the fluid so that it is more easily removed from the fracture, and to also remove any partially broken remnants of polymers or other additives used to viscosify the fracturing fluid by flow back to the wellbore during the clean-up or production periods. Once the polymers are broken down by the breaker and are reverted into a low viscosity fluid, the broken down carrier fluid is flowed back to remove it from the formation.
However, some broken down polymers and other materials that make up the fracturing fluid tend to adhere to the proppant and/or the formation. These materials tend to hold water and therefore occupy a significant volume. The result of these partially hydrated stagnant fracturing fluid components that surround the proppant within the fracture porosity and within the formation diminishes their permeability to hydrocarbons, acting as a restriction or barrier to hydrocarbon migration from the formation into the fracture and on to the wellbore. Additionally, this fluid saturation of the pore spaces is further compounded by adhesive or cohesive forces that cause the residue to be more difficult to dislodge, and the fluid-saturated zones restrict or prevent hydrocarbon flow to the wellbore. The rate of flow of hydrocarbon production from a formation is naturally dependent on numerous reservoir factors such as reservoir pressure, permeability, and hydrocarbon fluid viscosity. The contamination of the formation porosity and the fracture porosity by broken down polymers and other materials of the fracturing fluid is sometimes referred to as decreasing the effective fracture length. If a portion of the propped fracture cannot flow or “clean up” adequately, the net result is a portion of the propped fracture length is ineffective and does not contribute adequately to production, and the apparent result is that the “effective” portion of the propped fracture is less that the actual propped fracture length. The “trapped” fracturing fluid in the fracture is harmful to hydrocarbon production since it plugs the fracture and therefore impedes the flow of hydrocarbon.
Most efforts to address the problem of stagnant fracturing fluid in the fracture or formation that damages the permeability of hydrocarbon have focused on achieving a greater degree of degradation of high molecular weight polymers and/or the crosslink sites. Some of these high molecular-weight polymers typically contain insoluble or partially soluble materials that tend to serve as filler in the formation or fracture porosity after breaking the fracturing fluid (viscosity reduction). Sometimes, a breaker is used to destroy the molecular backbone of these polymers and reduce their molecular weight, rendering them ineffective in viscosifying the water, much smaller in size, and easier to move through the porosity and be removed from the porosity. Historically, less than 50% of the gel polymer of a stimulation treatment is returned to the surface during post-treatment cleanup.
Some efforts to address the problem of stagnant fracturing fluid in the formation have focused on finding a viscosifying agent that can be effective at a lower concentration to viscosity the fracturing fluid. According to this theory, if it were possible to use a lower concentration of a viscosifying agent, then a lower concentration of insoluble material would be present that requires breaking and would leave less residue in the formation after breaking. Still, reducing the concentration of the viscosifying agent has not always been found to be practical. Currently, the available viscosifying agents that might be effective at significantly lower concentration than traditional agents such as guar are far too costly, and still cannot provide adequate viscosity under downhole conditions regardless of higher cost.
Other efforts have focused on the development of thickening additives that do not form permanent bonds between the base chemical additives. This would theoretically allow for smaller sized structures, e.g., on the order of microscopic in size, to improve the ability of the material to flow back out of the fracture and/or the proppant pack.
Still other efforts to address the problem of stagnant fracturing fluid in the formation have focused on using a surfactant-based viscosifying agent rather than polymers such as guar to viscosify fracturing fluids. These viscosifying surfactants are selected to have low adhesion to proppant, thereby facilitating recovery of the fracturing fluid from the formation after the formation is fractured. For example, a system that does not use conventional guar-based polymers to viscosify the fracturing fluid is disclosed in U.S. Pat. No. 5,551,516, issued Sep. 3, 1996 to Schlumberger Technology Corporation. This patent discloses a viscoelastic surfactant based aqueous fluid systems that are useful in fracturing subterranean formations penetrated by a wellbore. The preferred thickening agents are quaternary ammonium halide salts derived from certain waxes, fats and oils. The thickening agent is used in conjunction with an inorganic water soluble salt such as ammonium chloride or potassium chloride, and an organic stabilizing additive selected from the group of organic salts such as sodium salicylate. The resulting fluids are claimed to be stable to a fluid temperature of about 225 degrees F. See U.S. Pat. No. 5,551,516, Abstract. Such a viscoelastic surfactant system is claimed to flow back the fracturing fluid more effectively after delivering the proppant due to lower molecular weight (size). However, these surfactant-based fracturing fluids are highly costly compared to conventional guar-based fracturing fluids and often have excessive leak-off into the formation porosity. They also require contact with liquid hydrocarbons to begin their breaking process, and in cases of dry gas reservoirs, these frac fluids have been known to not break at all. In these cases and as a preventative, a mutual solvent usually ethylene glycol mono butyl ether (EGMBE) or similar solvent is added as pre-flush to encourage breaking of these viscoelastic materials.
In addition, U.S. Pat. No. 6,439,309 issued Aug. 27, 2002 discloses silyl-modified polyamides, and subterranean formation treatments employing silyl-modified polyamides to minimize migration or movement of solid particulates within a subterranean formation and/or within a wellbore penetrating a subterranean formation. U.S. Pat. No. 6,439,309, Abstract. These coatings are described as being self-hardening to a substantially non-tacky state to which additional individual particulates will not adhere and to have a substantially pliable in situ elastic modulus under downhole conditions.
Thus, there has been a long-felt need for improved fluids and methods for more completely removing the guar-based fracturing fluids from the formation.